1. Technical Field
The present invention relates to a process for enhancing the recovery of liquid hydrocarbons from a subterranean formation which contains fractures, and more particularly, to such a process wherein a polymer enhanced foam is injected into a subterranean formation via a well and preferentially flows into and within fractures present in a subterranean formation.
2. Description of Related Art
Conventionally, liquid hydrocarbons are produced to the surface of the earth from a subterranean hydrocarbon-bearing formation via a well penetrating and in fluid communication with the formation. Usually, a plurality of wells are drilled and placed in fluid communication with the subterranean hydrocarbon-bearing formation to effectively produce liquid hydrocarbons from a particular subterranean reservoir. Approximately 5 to 25 volume percent of the liquid hydrocarbons originally present within a given reservoir in a subterranean formation usually can be produced by the natural energy of the reservoir, i.e., by primary production. Accordingly, secondary and tertiary recovery processes have usually been employed to produce additional quantities of original hydrocarbons in place from a subterranean formation once primary production becomes uneconomical or ceases. Such secondary recovery processes include processes involving the injection of a drive fluid, such as water, polymer thickened water, steam, foam or a gas, for example CO.sub.2, via wells designated as injection wells into the formation to drive liquid hydrocarbons to proximate wells designated for production of hydrocarbons to the surface. Successful secondary recovery processes may result in the recovery of greater than about 25 volume percent of the original liquid hydrocarbons in place within a given reservoir in a subterranean formation. Tertiary recovery processes have been utilized to recover an additional incremental amount of the original liquid hydrocarbons in place in a subterranean formation by altering the properties of reservoir fluids, e.g., altering interfacial tension, and thereby improving the displacement efficiency of liquid hydrocarbons from the formation. Examples of tertiary recovery processes include micellar and surfactant flooding processes. Tertiary recovery processes may also include processes which involve the injection of a thermal drive fluid, such as steam, or a gas, such as carbon dioxide, which at high pressures is miscible with liquid hydrocarbons. Such tertiary recovery processes can be applied to a given subterranean formation before or after a secondary recovery process has been operated to its economic limit, i.e., the revenue from the sale of hydrocarbons produced as a result of the process is less than the operating expense of the process per se.
One problem often encountered in conducting secondary or tertiary recovery processes is poor conformance, and thus sweep efficiency, of drive fluid injected into a subterranean formation during a secondary or tertiary process. Such poor conformance of drive fluid may occur where the matrix of the formation exhibits a lack of homogeneity. For example, layering of subterranean zones, strata, or beds of varying permeabilities, may occur in the near, intermediate and/or far well bore environment of a formation. Drive fluid injected into the formation via a well in fluid communication with the formation tends to preferentially channel or finger into and within high permeability streaks in the matrix and thus may result in extremely poor conformance and flow profiles of the drive fluid and reduced production and recovery of liquid hydrocarbons. Further exemplary, subterranean zones, strata, or beds possessing relatively high permeability may be vertically juxtaposed to subterranean zones, strata, or beds of relatively low permeability. Fluid injected into the subterranean hydrocarbon-bearing formation will preferentially flow through the zones, strata, or beds of relatively high permeability resulting in a relatively high liquid hydrocarbon content in the remaining zones of relatively low permeability.
Selective placement of a plugging or mobility reducing material in the regions of a subterranean formation exhibiting relatively high permeability has been suggested to improve conformance and flow profiles of drive fluids injected into the formation. More specifically, several prior art processes have been proposed to improve conformance and flow profiles of drive fluids injected into a subterranean formation by placing a foam in the relatively high permeability regions of the formation matrix. U.S. Pat. No. 4,676,316 to Mitchell discloses sequentially injecting an aqueous solution of water-soluble polymer and surfactant followed by a soluble or miscible gas into the matrix of a subterranean hydrocarbon-bearing reservoir. The polymer is selected from the group consisting of naturally occurring biopolymers, such as polysaccharides, and synthetic polymers, such as polyacrylamides, and is incorporated into the aqueous solution in an amount of from about 250 ppm to about 4,000 ppm. The surfactant which is a foam former and is chemically and thermally stable under reservoir conditions is added to the aqueous solution in an amount of from about 0.05 percent to about 2 percent. The gas is a soluble gas or a miscible gas which is injected into the formation under a pressure which is sufficient to effect miscibility with hydrocarbon deposits. The aqueous solution is introduced as a slug having a volume which is from about 0.05 pore volume to about 1 pore volume of the portion of the reservoir affected by the pattern. Thereafter, a drive fluid may be used to displace oil and the previously injected fluids towards production well(s). This process impedes the frontal flow of a flood in a subterranean reservoir in higher permeability regions thereof. U.S. Pat. No. 4,813,484 to Hazlett discloses injecting an aqueous solution containing a surfactant, a decomposable chemical blowing agent, and a water-thickening amount of a water-soluble polymer or gel into the more permeable zone(s) of a subterranean formation. The formation temperature, coinjected activators, reservoir fluids, or formation mineralogy causes the blowing agent to decompose and generate a gas. This gas forms bubbles which close pores in the more permeable zone(s) of a formation causing a subsequently injected drive fluid to be directed into less permeable zone(s). The injection rate of the aqueous solution must be sufficient to allow fluid placement into the more permeable zone(s). U.S. Pat. No. 3,530,940 to Dauber et al. discloses the sequential injecting into a subterranean formation an aqueous solution of a water-soluble film-forming polymer, such as polyvinyl alcohol or a polyvinyl pyrrolidone, and a gas to form foam within the pores of the formation thereby plugging the formation.
Use of foams to plug more permeable zones of a subterranean formation matrix have not proved to be completely satisfactory. Since the viscosity of most foams is often too high to permit effective injection within the high permeability zone, placement of such foams within the high permeability zones in the matrix of the subterranean formation usually requires the generation of the foam in situ within the high permeability zone. Accordingly, the gaseous and liquid components of a foam must be introduced into the formation matrix separately or sequentially. However, the mixing and resultant foam formation achieved by contacting an aqueous solution and a gas within the high permeability zones of a subterranean formation matrix is not as complete, uniform, or efficient as that which can be achieved prior to entry into the formation.
Further, poor conformance of a drive fluid often occurs in fractured subterranean formations since the drive fluid preferentially flows through the relatively high permeability fractures thereby bypassing the formation matrix. Thus, liquid hydrocarbons present within the formation matrix are not efficiently displaced by the drive fluid. Especially problematic is the poor conformance of drive gases which are injected into a naturally fractured subterranean formation.
Another problem associated with secondary recovery processes may be encountered in many fractured subterranean formations in which the fractures contain relatively viscous liquid hydrocarbon. After an aqueous drive fluid, such as water, which is initially injected into a vertically fractured subterranean formation breaks through to a production well, the volume percentage of viscous liquid hydrocarbons remaining in place in substantially vertically oriented and relatively high permeability fractures present within the subterranean formation often is significant, e.g., 5-70% or more. Continued injection of an aqueous drive fluid will only sweep a small amount of the remaining viscous liquid hydrocarbons from these fractures since the relatively high density and low viscosity of the aqueous drive fluid will often cause the drive fluid to flow under and thereby inefficiently displace the viscous liquid hydrocarbons present in the vertical fractures. Thus, upon breakthrough of the aqueous drive fluid at a production well, a water-soluble polymer, such as a polyacrylamide having a molecular weight of about 11,000,000, may be added to the aqueous drive fluid in an amount sufficient to significantly increase the viscosity of the drive fluid, for example 500 ppm. However, injection of such thickened drive fluids may not result in a substantial increase in the recovery efficiency of viscous liquid hydrocarbons residing in vertical fractures. The relatively high density of thickened drive fluids causes the drive fluid to tend to flow underneath and thus inefficiently displace unrecovered liquid hydrocarbons present in vertical fractures within a subterranean formation. Attempts to obtain acceptable liquid hydrocarbon recovery levels by further increasing polymer concentration in thickened drive fluids to increase fluid viscosity and thereby obtaining more favorable fluid:oil mobility ratios have proved to be uneconomical and inefficient. Thus, a need exists for a process, utilized alone or in combination with secondary or tertiary recovery processes, which can effectively and economically recover liquid hydrocarbons from a fractured subterranean formation.
Accordingly, it is an object of the present invention to provide an efficient and economic process for recovering liquid hydrocarbons present in subterranean fractures.
It is also an object of the present invention to provide a process for increasing the recovery liquid hydrocarbons present in fractures in a vertically fractured subterranean formation which are in fluid communication with an underlying aquifer.
Another object of the present invention is to provide a process for recovering liquid hydrocarbons present in a fractured subterranean formation wherein a drive fluid which is subsequently injected into the formation is caused to preferentially flow into the formation matrix.
Another object of the present invention to provide a process for increasing the recovery of liquid hydrocarbons from a vertically fractured subterranean formation which utilizes imbibition of water into the formation matrix as a hydrocarbon recovery mechanism.
A further object of the present invention to provide a process for improving the flow profiles of a drive fluid injected into a subterranean formation via a well in fluid communication therewith.
A further object of the present invention is to provide a relatively inexpensive yet effective mobility control fluid for flooding of fractures present in a fractured subterranean formation.
A still further object of the present invention is to provide a process for recovering liquid hydrocarbons from a fractured subterranean formation in which a fully formed foam is injected into the formation thereby obviating the need for sequential injection of foam-forming solutions.
It is also an object of the present invention to utilize non-hazardous components to form a polymer enhanced foam.
It is another object of the present invention to provide a polymer enhanced foam for the processes described herein which is exceptionally stable, has a relatively high viscosity and is relatively insensitive to surfactant chemistry.
It is another object of the present invention to form a polymer enhanced foam without using film forming polymers which are relatively expensive and/or difficult to dissolve.